System and method for producing liquefied natural gas

ABSTRACT

A system, and a method for producing liquefied natural gas are provided. The system includes a heat exchanger, a first supersonic chiller, and a compression unit. The heat exchanger is for cooling a feed natural gas stream to obtain a cooled natural gas stream. The first supersonic chiller is for chilling the cooled natural gas stream to produce liquefied natural gas and output at least a portion of chilled gaseous natural gas to the heat exchanger to be heated to obtain a heated natural gas stream. The compression unit is for compressing the heated natural gas stream from the heat exchanger and providing a compressed natural gas stream to the heat exchanger to be cooled together with the feed natural gas stream by heat exchanging with the at least a portion of the chilled gaseous natural gas.

BACKGROUND

Embodiments of the invention relate to systems and methods for producing liquefied natural gas (LNG).

Natural gas is a fossil fuel used as a source of energy for heating, cooking, and electricity generation. It is also used as fuel for vehicles and as a chemical feedstock in the manufacture of plastics and other commercially important organic chemicals. The volume of natural gas is reduced after liquefied. The volume of LNG is about 1/625 of the volume of the gaseous natural gas, so the LNG is easily stored and transported. A traditional LNG producing system uses a cold box to liquefy natural gas. The cold box uses nitrogen (N₂), methane (CH₄), or a mixed refrigerant including, but not limited, N₂, CH₄, C₂H₆, and/or C₃H₈, etc, as refrigerants cycling therein to cool down the natural gas flowing through the cold box, which has high cost and a large size.

It is desirable to provide a system and a method of producing liquefied natural gas to address the above-mentioned problem.

BRIEF DESCRIPTION

In accordance with one embodiment disclosed herein, a system is provided. The system includes a heat exchanger, a first supersonic chiller, and a compression unit. The heat exchanger is for cooling a feed natural gas stream to obtain a cooled natural gas stream. The first supersonic chiller is for chilling the cooled natural gas stream to produce liquefied natural gas and output at least a portion of chilled gaseous natural gas to the heat exchanger to be heated to obtain a heated natural gas stream. The compression unit is for compressing the heated natural gas stream from the heat exchanger and providing a compressed natural gas stream to the heat exchanger to be cooled together with the feed natural gas stream by heat exchanging with the at least a portion of the chilled gaseous natural gas.

In accordance with another embodiment disclosed herein, a method is provided. The method includes cooling a feed natural gas stream to obtain a cooled natural gas stream; producing, via a first supersonic chiller, liquefied natural gas using the cooled natural gas stream and outputting the liquefied natural gas and chilled gaseous natural gas from the first supersonic chiller; heating at least a portion of the chilled gaseous natural gas; compressing the heated natural gas stream to obtain a compressed natural gas stream; and cooling the compressed natural gas stream together with the feed natural gas stream by heat exchanging with the at least a portion of the chilled gaseous natural gas.

DRAWINGS

These and other features and aspects of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

FIG. 1 is a schematic diagram of a system for producing LNG in accordance with an embodiment;

FIG. 2 is a schematic diagram of a system for producing LNG in accordance with another embodiment;

FIG. 3 is a schematic diagram of a system for producing LNG in accordance with another embodiment;

FIG. 4 is a schematic diagram of a system for producing LNG in accordance with another embodiment;

FIG. 5 is a schematic diagram of a system for producing LNG in accordance with another embodiment;

FIG. 6 is a schematic diagram of a system for producing LNG in accordance another embodiment;

FIG. 7 is a schematic diagram of a system for producing LNG in accordance with another embodiment;

FIG. 8 is a schematic diagram of a system for producing LNG in accordance with another embodiment;

FIG. 9 is a schematic diagram of a system for producing LNG in accordance with another embodiment; and

FIG. 10 is a flow chart of a method of producing the LNG in accordance with an embodiment.

DETAILED DESCRIPTION

Unless defined otherwise, technical and scientific terms used herein have the same meaning as is commonly understood by one of ordinary skill in the art to which this disclosure belongs. The terms “a” and “an” do not denote a limitation of quantity, but rather denote the presence of at least one of the referenced items. The use of “including,” “comprising” or “having” and variations thereof herein are meant to encompass the items listed thereafter and equivalents thereof as well as additional items. The terms “first”, “second” and the like in the description and the claims do not mean any sequential order, number or importance, but are only used for distinguishing different components.

Ranges may be expressed herein as from “about” one particular value, and/or to “about” another particular value. When such a range is expressed, another embodiment includes from the one particular value and/or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent “about,” it will he understood that the particular value forms another embodiment. It will be further understood that the endpoints of each of the ranges are significant both in relation to the other endpoint, and independently of the other endpoint.

The term “gas” is used interchangeably with “vapor,” and means a substance or mixture of substances in the gaseous state as distinguished from the liquid or solid state. Likewise, the term “liquid” means a substance or mixture of substances in the liquid state as distinguished from the gas or solid state.

The term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C1) as a significant component. Raw natural gas may also typically contain ethane (C2), higher molecular weight hydrocarbons, one or more acid gases (such as carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon disulfide, and mercaptans), and minor amounts of contaminants such as water, helium, nitrogen, iron sulfide, wax, and crude oil. The composition of the raw natural gas can vary.

“Acid gases” are contaminants that are often encountered in natural gas streams. Typically, these gases include carbon dioxide (CO₂) and hydrogen sulfide (H₂S), although any number of other contaminants may also form acids. Acid gases are commonly removed by contacting the gas stream with an absorbent, such as an amine, which may react with the acid gas. When the absorbent becomes acid-gas “rich,” a desorption step can be used to separate the acid gases from the absorbent. The “lean” absorbent is then typically recycled for further absorption.

“Liquefied natural gas” or “LNG” is a cryogenic liquid form of natural gas generally known to include a high percentage of methane, but may also include trace amounts of other elements and/or compounds including, but not limited to, ethane, propane, butane, carbon dioxide, nitrogen, helium, hydrogen sulfide, or combinations thereof. The natural gas may have been processed to remove one or more components (for instance, acid gas) or impurities (for instance, water and/or heavy hydrocarbons) and then cooled into the liquid at almost atmospheric pressure by cooling.

“Heavy hydrocarbons” are the hydrocarbons having carbon number higher than or equal to three, which may be referred as to “higher carbon number hydrocarbons” or abbreviated as “C3+”. Heavy hydrocarbons may include propane (C₃H₈), normal butane C₄H₁₀), isobutane (i-C₄H₁₀), pentanes and even higher molecular weight hydrocarbons.

“Natural gas liquid” (NGL) is a cryogenic liquid generally known to include a high percentage of heavy hydrocarbons, but may also include trace amounts of other elements and/or compounds including, but not limited to, methane ethane, carbon dioxide, nitrogen, helium, hydrogen sulfide, or combinations thereof.

“Compressor” refers to a device for compressing gases, and includes pumps, compressor turbines, reciprocating compressors, piston compressors, rotary vane or screw compressors, and devices and combinations capable of compressing gases.

“Heat exchanger” refers to any column, tower, unit or other arrangement adapted to allow the passage of two or more streams and to affect direct or indirect heat exchange between the two or more streams. Examples include a tube-in-shell heat exchanger, a cryogenic spool-wound heat exchanger, or a brazed aluminum-plate fin type, among others.

“Supersonic chiller” (or referred as to “supersonic swirling separator”) is a device mainly using a convergent-divergent Laval Nozzle, in which the potential energy (pressure and temperature) of gas transforms into kinetic energy (velocity) of the gas. The velocity of the gas reaches supersonic values. Thanks to gas acceleration, sufficient temperature and pressure drops are obtained, thereby target component(s) in the gas is liquefied. The liquefied target component is separated from the gas through highly swirling. Then the high velocity is slowed down and the pressure is recovered to some of the initial pressure. The Laval Nozzle may be designed to liquefy the target components according to the particular target components.

“Pressure reducing device” refers to a device for expanding a stream, thereby reducing its pressure and temperature. “Joule-Thomson (J-T) valve” is one type of the pressure reducing device which utilizes the Joule-Thomson principle that expansion of gas will result in an associated cooling of the gas. in various embodiments described herein, a J-T valve may he substituted by other expansion devices, such as turbo-expanders, and the like.

“Separation vessel” is a vessel wherein an incoming gaseous and liquid phases feed is separated into individual gaseous and liquid fractions. Typically, the vessel has sufficient cross-sectional area so that the vapor and liquid are separated by gravity.

“Substantial” when used in reference to a quantity or amount of a material, or specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.

FIG. 1 illustrates a schematic diagram of a system 100 for producing LNG in accordance with an embodiment. The system 100 includes a heat exchanger 26, a first supersonic chiller 30 and a compression unit 21. The heat exchanger 26 is configured to cool a feed natural gas stream to obtain a cooled natural gas stream 28. The first supersonic chiller 30 is configured to chill the cooled natural gas stream 28 to produce the LNG and output at least a portion of chilled gaseous natural gas to the heat exchanger 26 to be heated to obtain a heated natural gas stream 60. The compression unit 21 is configured to compress the heated natural gas stream 60 and provide the compressed natural gas stream 62 to the heat exchanger 26 to be cooled together with the feed natural gas stream by heat exchanging with the at least a portion of the chilled gaseous natural gas.

In the illustrated embodiment, the system 100 includes a purification unit 13 receiving a raw natural gas stream 11, which may use any number of processes to remove acid gases and other contaminates 15. The purification unit 13 may be a cryogenic distillation unit, such as a Ryan-Holmes processing system. Other cryogenic distillation techniques and systems may be used, such as the controlled freeze zone (CFZ) techniques. Non-cryogenic techniques and systems may also be used for purification, such as a warm gas processing; system, an amine sweetening processing system. The acid gases 15 from the purification unit 13 may be utilized in other systems/processes. For example, a CO₂ stream may be used for enhanced oil recovery or a H₂S stream may be used to produce sulfur using the Claus process. In an embodiment, in addition to removing acid gases 15, the purification unit 13 may also remove the heavy hydrocarbons, which may also be utilized in other systems/processes.

A purified natural gas stream 17 from the purification unit 13 is fed to a dehydration unit 19 in which water vapor may be removed using glycol dehydration, desiccants, or Pressure Swing Adsorption (PSA), among other processes. In some embodiments, the dehydration unit 19 may precede the purification unit 13.

A dehydrated natural gas stream 20 from the dehydration unit 19 is fed to a compression unit 21 in which the dehydrated natural gas stream 20 is compressed. The compression unit 21 may include one or more compressors to compress gases to an expected pressure. In the illustrated embodiment, the compression unit 21 includes a first compressor 22 and a second compressor 23, and the dehydrated natural gas stream 20 flows through the first compressor 22 to be compressed. In an embodiment, the compressor 22 increases the pressure of the dehydrated natural gas stream 20 from about 54 bar to about 200-250 bar. The pressure of the dehydrated natural gas stream 20 may vary according to particular applications. In an embodiment, the second compressor 23 is configured to compress the heated natural gas stream 60 to obtain a stream 61, and the stream 61 is mixed with the dehydrated natural gas stream 20 and compressed by the first compressor 22. The illustrated embodiment is only a non-limited example, but in sonic other embodiments different compression unit and different compressors may be utilized. For example, the heated natural Las stream 60 and the dehydrated natural gas stream. 20 may he compressed respectively by different compressors and mixed together in the heat exchanger 26.

The compressed natural gas stream 62 from the compression unit 21 is fed to a heat exchanger 26 in which the compressed natural gas stream 62 is cooled. The heat exchanger 26 includes a first channel 25 and a second channel 27. In an embodiment, the heat exchanger 26 facilitates heat exchanging between gases passing through the first channel 25 and gases passing through the second channel 27. The first channel 25 receives and cools the compressed natural gas stream 24 from the compression unit 21. In an embodiment, the heat exchanger 26 cools the compressed natural gas stream 62 from about 45° C. to about 6° C., but it is not limited. The temperature may vary in other embodiments.

In some other embodiments, the raw natural gas stream 11 may be treated by one or some of the purification units 13, the dehydration unit 19, the compression unit 21, or treated by any other devices which are not shown in FIG. 1 before fed to the heat exchanger 26. The feed natural gas stream may be the raw natural gas stream 11, the purified natural gas stream 17, the dehydrated natural gas stream 20, or the compressed natural gas stream 62.

A cooled natural gas stream 28 from the heat exchanger 26 is fed to a first supersonic chiller 30. The first supersonic chiller 30 is configured to chill the cooled natural gas stream 28 to produce the LNG and output chilled gaseous natural gas. Most portion of the cooled natural gas stream 28 is liquefied to the LNG and some portion of the cooled natural gas stream 28 is not liquefied and output from the first supersonic chiller 30 in gaseous state. At least a portion of the chilled gaseous natural gas from the first supersonic chiller 30 is recycled to produce the LNG in the system 100. The second channel 27 of the heat exchanger 26 is for receiving and heating the recycled portion of the chilled gaseous natural gas.

The first supersonic chiller 30 includes a first outlet 34 outputting a first portion 38 of the chilled gaseous natural gas and a second outlet 36 for outputting a mixture stream 32 including the LNG in the liquid phase and another portion of the chilled gaseous natural gas in the gaseous phase. Most portion of the chilled gaseous natural gas is output from the first outlet 34 and the rest portion of the chilled gaseous natural gas mixed in the LNG is output from the second outlet 36. The first supersonic chiller 30 is utilized to produce the LNG instead of the traditional cold box, which has smaller size than the cold box, so that the system 100 is compact and simpler.

In an embodiment, at least one separation vessel is in communication with the second outlet 36 of the first supersonic chiller 30 and configured to separate at least a portion of the chilled gaseous natural gas from the mixture stream 32. In the illustrated embodiment, a first separation vessel 40 is configured to separate a second portion 42 of the chilled gaseous natural gas from the mixture stream 32. A separated stream 44 from the first separation vessel 40 includes the LNG.

In an embodiment, the separated stream 44 is fed to a first pressure reducing device 46 in communication with the first separation vessel 40 for reducing a pressure of the separated stream 44 from the first separation vessel 40 and outputting a gas-liquid mixture 48 of liquefied natural gas and low pressure gaseous natural gas. In an embodiment, the first pressure reducing device 46 reduces the pressure of the separated stream 44 from about 60-80 bar to about 1-3 bar, but it is not limited. The natural gas 44 at high pressure, such as about 60-80 bar, is liquid, but a portion of the natural gas is gaseous at low pressure, such as about 1-3 bar, so the mixture 48 from the first pressure reducing device 46 is a gas-liquid mixture stream of natural gas. The first pressure reducing device 46 reduces the pressure of the liquefied natural gas 44 to a pressure, such as about 1-3 bar, at which the LNG is easily stored and transported. Typically, the first pressure reducing device 46 is a J-T valve.

A pressure reducing stream 48 from the first pressure reducing device 46 is fed to a second separation vessel 50 for separating the low pressure gaseous natural gas 54 from the gas-liquid mixture 48 from the first pressure reducing device 46. A stream 52 output from the second separation vessel 50 is substantially the LNG and has a pressure at which the LNG is easily stored and transported. The LNG stream 52 from the second separation vessel 50 may be the product of the system 100 which may be stored or provided to downstream system (not shown). The low pressure gaseous natural gas 54 has a lower pressure than the pressures of the first portion 38 and the second portion 42 of the chilled gaseous natural gas. In an embodiment, the first portion 38 and the second portion 42 of the chilled gaseous natural gas have the pressure of about 60-80 bar, and the low pressure gaseous natural gas 54 has the pressure of about 1-3 bar.

The system 100 includes a collection device 56 for receiving the first portion 38, the second portion 42 of the chilled gaseous natural gas and the low pressure gaseous natural gas 54, and outputting a recycled stream 58 (or referred as to a collection stream) of the portions 38, 42, and the low pressure gaseous natural gas 54 at a pressure in a range of about 40 bar to about 60 bar, to the second channel 27 of the heat exchanger 26. In an embodiment, the collection device 56 is an ejector which may use Venturi effect of a converging-diverging nozzle.

The heat exchanger 26 heats the recycled stream 58 through heat exchanging with gases through the first channel 25 thereof. The heat exchanger 26 cools the compressed natural gas stream 62 through the first channel 25 by heat exchanging with the recycled stream 58 through the second channel 27. The compressed natural gas stream 62 is cooled to the expected temperature totally by heat exchanging with the recycled stream 58 through the second channel 27 of the heat exchanger 26 without any other cooling resources or refrigerants. The cold energy obtained by the compressed natural gas stream 62 is substantially equal to the cold energy supplied by the recycled stream 58. In an embodiment, the compressed natural gas stream 62 are cooled from about 45° C. to about 6° C., and the recycled stream 58 is heated from about −15° C. to about 36° C., but it is not limited.

FIG. 2 illustrates a schematic diagram of a system 200 for producing LNG in accordance with another embodiment. The system 200 in FIG. 2 is similar to the system 100 in FIG. 1. Differences of the system 200 in FIG. 2 from the system 100 will be described in subsequent paragraphs. The dehydrated natural gas stream 220 from the dehydration unit 219 is fed to the heat exchanger 226 without being compressed, which may he at about 54 bar for example. In an embodiment, the first compressor 22 in FIG. 1 is omitted. The heat exchanger 226 cools the dehydrated natural gas stream 220 to a lower temperature, such as about −35° C., than the temperature in FIG. 1 such as 6° C.

The system 200 includes a third separation vessel 264 in communication with the heat exchanger 226 for receiving the cooled natural gas stream 228 from the first channel 225 of the heat exchanger 226 and separating the NGL 266 from the cooled natural gas stream 228. The separated natural gas stream 268 from the third separation vessel 264 is fed to the first supersonic chiller 230 to generate the LNG. When the raw natural gas stream 211 does not include the heavy hydrocarbons or includes mirror amount of heavy hydrocarbons, the third separation vessel 264 can be omitted.

The system 200 includes a cooling device 270 for cooling at least a portion of the chilled gaseous natural gas from the first supersonic chiller 230 to the heat exchanger 226. The portion of the chilled gaseous natural gas cooled by the cooling device 270 includes the first portion 238 and the second portion 242 of the chilled gaseous natural gas at substantially same or approximate pressure. In an embodiment, the third portion 254 of the chilled gaseous natural gas may be discharged, which is at different pressure from the pressure of the first portion 238 and the second portion 242 of the chilled gaseous natural gas. In another embodiment, the first portion 238, the second portion 242 and the third portion 254 may be collected by the collection device 56 in FIG. 1 and then cooled by the cooling device 270. In the illustrated embodiment, the cooling device 270 is a second pressure reducing device, which typically is a J-T valve. The second pressure reducing device can cool gases and expand the gases meanwhile. In an embodiment, the recycled stream 258 is at a pressure of about 4 bar.

The recycled stream 258 from the cooling device 270 is fed to the second channel 227 of the heat exchanger 226 to be heated to a temperature approximate to the temperature of the dehydrated natural gas stream 220. The heated recycled stream 260 from the heat exchanger 226 is compressed by the compression unit 221 and the compressed recycled stream 262 is recycled to the dehydrated natural gas stream 220. The compression unit 221 compresses the heated recycled stream 260 to a pressure approximate to the pressure of the dehydrated natural gas stream 220. In an embodiment, the second compressor 223 compresses the heated recycled stream 260 from about 4 bar to about 54 bar, which is designed differently from the second compressor 23 in FIG. 1.

The heat exchanger 226 cools the dehydrated natural gas stream 220 and the compressed recycled stream 262 by heat exchanging with the recycled stream 258 through the second channel 227. Accordingly, the cooling device 270 cools the first portion 238 and the second portion 242 of the chilled gaseous natural gas to a temperature, e.g., about −62° C., lower than the temperature of the cooled natural gas stream 228 to make sure the dehydrated natural gas stream 220 and the compressed recycled stream 262 can be cooled to the expected temperature by the first portion 238 and the second portion 242 of the chilled gaseous natural gas through heat exchanging.

FIG. 3 illustrates a schematic diagram of a system 300 for producing LNG in accordance with another embodiment. The system 300 in FIG. 3 is similar to the system 200 in FIG. 2. The main difference of the system 300 in FIG. 3 from the system 200 in FIG. 2 is that the cooling device 372 of the system 300 is an expander for expanding and cooling the first portion 338 and the second portion 342 of the chilled gaseous natural gas. The expander has similar functions with the second pressure reducing device 270 in FIG. 2.

FIGS. 2 and 3 only show two examples of the cooling device, but the cooling device may be any other devices capable of cooling gases.

FIG. 4 illustrates a schematic diagram of a system 400 for producing the LNG in accordance with another embodiment. The system 400 in FIG. 4 is similar to the system 100 in FIG. 1. The main difference of the system 400 in FIG. 4 from the system 100 is that the system 400 in FIG. 4 includes a second supersonic chiller 474, a fourth separation vessel 475 and a third compressor 476. The second supersonic chiller 474 is for removing the NGL 478 from the natural gas stream. In the illustrated embodiment, the dehydration unit 419 is positioned upstream of the second supersonic chiller 474. The dehydrated natural gas stream 420 including the heavy hydrocarbons is fed to the second supersonic chiller 474. The heavy hydrocarbons are liquefied to generate the NGL 478 and the NGL 478 is separated from the dehydrated natural gas stream 420 in the second supersonic chiller 474. In an embodiment, some natural gas is mixed in the NGL 478, and the fourth separation vessel 475 separates at least a portion of the natural gas from the NGL 478. The separated natural gas 479 from the fourth separation vessel 475 is mixed to the natural gas stream 480 output from the second supersonic chiller 474 and flows into the third compressor 476.

The second supersonic chiller 474 is designed differently from the first supersonic chiller 430. A mach number of the second supersonic chiller 474 is in a range of 1.1 to 1.6, while the mach number of the first supersonic chiller 430 is in a range of 2 to 3. The natural gas stream 480 and the separated natural gas 479 have a temperature of about 20-35° C. and a pressure of about 30-40 bar, while the chilled gaseous natural gas stream 438 output from the first supersonic chiller 430 has a temperature of about −5-0° C. and a pressure of about 60-80 bar.

The pressure of the natural gas stream 480 from the second supersonic chiller 474 is lower than the pressure of the dehydrated natural gas stream 420, such as about 54 bar. The third compressor 476 is for compressing the natural gas stream 480 to provide a third compressed stream 482 at an expected pressure, such as about 100 bar, to the compression unit 421. In an embodiment, the third compressor 476 may be omitted, and the natural gas stream 480 from the second supersonic chiller 474 is compressed by the compression unit 421 to an expected pressure, such as about 210 bar, for the first supersonic chiller 430. Accordingly, the compression unit 421 in this embodiment may be designed differently from the compression unit 21 in FIG. 1.

FIG. 5 illustrates a schematic diagram of a system 500 for producing LNG in accordance with another embodiment. The system 500 in FIG. 5 is similar to the system 200 in FIG. 2. The main difference of the system 500 in FIG. 5 from the system 200 is that the system 500 includes the second supersonic chiller 574, the fourth separation vessel 575 and the third compressor 576 which are similar to the second supersonic chiller 474, the fourth separation vessel 475 and the third compressor 476 in FIG. 4. The second supersonic chiller 574 in FIG. 5 is also for removing the NGL from the dehydrated natural gas stream 520. The third compressor 576 is for compressing the natural gas stream 580.

FIG. 6 illustrates a schematic diagram of a system 600 for producing LNG in accordance with another embodiment. The system 600 in FIG. 6 is similar to the system 300 in FIG. 3. The main difference of the system 600 in FIG. 6 from the system 300 is that the system 600 includes the second supersonic chiller 674, the fourth separation vessel 675 and the third compressor 676 which are similar to the second supersonic chiller 574, the fourth separation vessel 575 and the third compressor 576 in FIG. 5.

In the embodiments of FIGS. 4 to 6, the third compressors 476, 576, 676 are positioned downstream of the second supersonic chillers 474, 574, 674. In another embodiment, the third compressors 476, 576, 676 may be positioned upstream of the second supersonic chillers 474, 574, 674 to compress the dehydrated natural gas streams 420, 520, 620 to a high pressure to make sure the natural gas streams 480, 580, 680 output from the second supersonic chillers 474, 574, 674 has the expected pressure.

FIG. 7 illustrates a schematic diagram of a system 700 for producing LNG in accordance with another embodiment. The system 700 in FIG. 7 is similar to the system 400 in FIG. 4. The main difference of the system 700 in FIG. 7 from the system 400 is that the dehydration unit 719 of the system 700 in FIG. 7 is positioned downstream of the second supersonic chiller 774. The second supersonic chiller 774 is for removing the NGL and at least a portion of water vapor 778 from the purified natural gas stream 717, and outputting a stream 786 including the natural gas and a portion of water vapor. The dehydration unit 719 is for removing water vapor from the stream 786 from the second supersonic chiller 774 to output the dehydrated natural gas stream 720. The size of the dehydration unit 719 in this embodiment is reduced due to the water vapor removing of the second supersonic chiller 774. The stream 778 may include some natural gas mixed in the NGL and the separated water vapor, and the fourth separation vessel 775 separates at least a portion of the natural gas from the stream 778.

The second supersonic chiller 774 in FIG. 7 may be designed differently from or the same as the second supersonic chiller 474 in FIG. 4 and differently from the first supersonic chiller 730 to remove the NGL and some water vapor. In an embodiment, the mach number of the second supersonic chiller 774 is in a range of 1.1 to 1.6. In an embodiment, the stream 786 output from the second supersonic chiller 774 in FIG. 7 has a temperature of about 2535° C. and a pressure of about 35-45 bar. In an embodiment, a compressor may be provided upstream or downstream of the second supersonic chiller 774 to increase the pressure of the natural gas, since the second supersonic chiller 774 reduces the pressure of the natural gas flowing through.

FIG. 8 illustrates a schematic diagram of a system 800 for producing the LNG in accordance with another embodiment. The system 800 in FIG. 8 is similar to the system 500 in FIG. 5. The main difference of the system 800 in FIG. 8 from the system 500 in FIG. 5 is that the dehydration unit 819 of the system 800 in FIG. 8 is positioned downstream of the second supersonic chiller 874. The second supersonic chiller 874, the fourth separation vessel 875 and the dehydration unit 819 in FIG. 8 are similar to the second supersonic chiller 774, the fourth separation vessel 775 and the dehydration unit 719 in FIG. 7.

FIG. 9 illustrates a schematic diagram of a system 900 for producing LNG in accordance with another embodiment. The system 900 in FIG. 9 is similar to the system 600 in FIG. 6. The main difference of the system 900 in FIG. 9 from the system 600 in FIG. 6 is that the dehydration unit 919 of the system 900 in FIG. 9 is positioned downstream of the second supersonic chiller 974. The second supersonic chiller 974, the fourth separation vessel 975 and the dehydration unit 919 in FIG. 9 are similar to the second supersonic chillers 774, 874, the fourth separation vessels 775, 875 and the dehydration units 719, 819 in FIGS. 7 and 8.

FIG. 10 illustrates a flow chart of a method 110 for producing LNG in accordance with an embodiment. The method 110 includes steps 111-115. In step 111, a feed natural gas stream is cooled to obtain a cooled natural gas stream. In step 112, the LNG is produced via a first supersonic chiller using the cooled natural gas stream and the LNG and a chilled gaseous natural gas is output from the first supersonic chiller. In step 113, at least a portion of the chilled gaseous natural gas is heated. In step 114, the heated natural gas stream is compressed. In step 115, the compressed natural gas stream is cooled together with the feed natural gas stream by heat exchanging with the chilled gaseous natural gas.

The order of the steps and the separation of the actions in the steps shown in FIG. 10 are not intended to he limiting. For example, the steps may be performed in a different order and an action associated with one step may be combined with one or more other steps or tray be sub-divided into a number of steps. One or more additional actions may be included before, between and/or after the method 110 in some embodiments.

While embodiments of the invention have been described herein, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims.

Furthermore, the skilled artisan will recognize the interchangeability of various features from different embodiments. The various features described, as well as other known equivalents for each feature, can be mixed and matched by one of ordinary skill in this art to construct additional systems and techniques in accordance with principles of this disclosure. 

1. A system, comprising: a heat exchanger for cooling a feed natural gas stream to obtain a cooled natural gas stream; a first supersonic chiller for chilling the cooled natural gas stream to produce liquefied natural gas and output at least a portion of chilled gaseous natural gas to the heat exchanger to be heated to obtain a heated natural gas stream; and a compression unit for compressing the heated natural gas stream and providing a compressed natural gas stream to the heat exchanger to he cooled together with the feed natural gas stream by heat exchanging with the at least a portion of the chilled gaseous natural gas.
 2. The system of claim 1, wherein the first supersonic chiller comprises a first outlet for outputting a first portion of the chilled gaseous natural gas and a second outlet for outputting a mixture stream comprising the liquefied natural gas and another portion of the chilled gaseous natural gas, and the system comprises at least one separation vessel in communication with the second outlet of the first supersonic chiller for separating at least a portion of the chilled gaseous natural gas from the mixture stream.
 3. The system of claim 2, wherein the at least one separation vessel comprises a first separation vessel for separating a second portion of the chilled gaseous natural gas from the mixture stream and outputting the liquefied natural gas, the system comprises a first pressure reducing device in communication with the first separation vessel for reducing a pressure of the liquefied natural gas from the first separation vessel and outputting a gas-liquid mixture including liquefied natural gas and low pressure gaseous natural gas, and the system comprises a second separation vessel for separating the low pressure gaseous natural gas from the gas-liquid mixture from the first pressure reducing device.
 4. The system of claim 3, comprising a collection device for receiving the first portion, the second portion of the chilled gaseous natural gas and the low pressure gaseous natural gas, and outputting a recycled stream of the first portion, the second portion and the low pressure gaseous natural gas at same pressure to the heat exchanger.
 5. The system of claim 1, comprising a third separation vessel in communication with the heat exchanger for removing a natural gas liquid from the cooled natural gas stream from the heat exchanger.
 6. The system of claim 1, comprising a cooling device for cooling the at least a portion of the chilled gaseous natural gas from the first supersonic chiller to the heat exchanger.
 7. The system of claim 6, wherein the cooling device comprises a second pressure reducing device.
 8. The system of claim 6, wherein the cooling device comprises an expander.
 9. The system of claim 1, comprising a second supersonic chiller for removing a natural gas liquid from the feed natural gas stream.
 10. The system of claim 9, comprising a dehydration unit positioned downstream of the second supersonic chiller, wherein the second supersonic chiller is for removing at least a portion of water vapor from the feed natural gas stream and the dehydration unit is for removing water vapor from the feed natural gas stream from the second supersonic chiller.
 11. The system of claim 9, comprising a dehydration unit positioned upstream of the second supersonic chiller for removing water vapor from the feed natural gas stream.
 12. A method, comprising: cooling a feed natural gas stream to obtain a cooled natural gas stream; producing, via a first supersonic chiller, liquefied natural gas using the cooled natural gas stream and outputting the liquefied natural gas and chilled gaseous natural gas from the first supersonic chiller; heating at least a portion of the chilled gaseous natural gas; compressing the heated natural gas stream to obtain a compressed natural gas stream; and cooling the compressed natural gas stream together with the feed natural gas stream by heat exchanging with the at least a portion of the chilled gaseous natural gas.
 13. The method of claim 12, wherein outputting the liquefied natural gas and the chilled gaseous natural gas comprises outputting a first portion of the chilled gaseous natural gas and outputting a mixture stream comprising the liquefied natural gas and another portion of the chilled gaseous natural gas, and the method comprises separating at least a portion of the chilled gaseous natural gas from the mixture stream.
 14. The method of claim 13, wherein the separating comprises, separating a second portion of the chilled gaseous natural gas from the mixture stream, reducing a pressure of the liquefied natural gas to obtain a gas-liquid mixture of liquefied natural gas and low pressure gaseous natural gas, and separating the low pressure gaseous natural gas from the gas-liquid mixture.
 15. The method of claim 14, comprising collecting the first portion, the second portion of the chilled gaseous natural gases and the low pressure gaseous natural gas at same pressure.
 16. The method of claim 12, comprising removing a natural gas liquid from the cooled natural gas stream.
 17. The method of claim 12, comprising cooling the at least a portion of the chilled gaseous natural gas from the first supersonic chiller before the heating.
 18. The method of claim 12, comprising removing, via a second supersonic chiller, a natural gas liquid from the feed natural gas stream before cooling the feed natural gas stream.
 19. The method of claim 18, comprising removing, via the second supersonic chiller, at least a portion of water vapor from the feed natural gas stream, and removing, via a dehydration unit, water vapor from the feed natural gas stream from the second supersonic chiller.
 20. The method of claim 18, comprising removing, via a dehydration unit, water vapor from the feed natural gas stream before removing the natural gas liquid. 